As illustrated in FIG. 1A, many oil reservoirs have an active bottom water zone 20 beneath a net-pay zone containing oil. If oil, particularly high viscosity in-situ oil, is pumped from a vertical well completed in the oil zone, water can cone up to the production well and inhibit production. In terms of production, coning will reduce oil cuts and increase water cuts until it is no longer economic to produce the well. In the industry, the well is said to have “watered off”. The mobility ratio of the oil determines the rate and extent of water coning. Typically, when the oil is heavier, the worse the water-coning problem is. As illustrated in FIG. 2, the problem may also be exhibited in SAGD for bitumen recovery with bottom water reservoirs.
Attempts have been made to prevent coning/cresting when reservoir characteristics are known. However, these attempts have had limited impact. Examples of attempts include the following:
1) The production well is completed higher up in the net pay zone, so the water cone has to be elongated before the well waters off. This is a temporary fix at best, and extra production is often marginal.
2) As illustrated in FIG. 1B, a horizontal well is drilled so the pressure drop of pumping is spread over the length of the horizontal well. However, water will eventually encroach to the well and produce a water crest zone 10 of high water saturation. Similar to a vertical well, the well will water off.3) Oil production rates are minimized to delay or prevent coning/cresting4) As illustrated in FIG. 3, downhole oil/water separator 30 (DHOWS) with downhole water disposal is installed. (Piers, K. Coping with Water from Oil and Gas Wells, CFER, Jun. 14, 2005). The downhole device can be a cyclone. This device, however, requires a suitable disposal zone 40 for water, and it works best on light oils with a high density difference between water and oil. This is not practical for heavier oils.5) As illustrated in FIG. 4, a reverse coning system 50 is installed (Piers, 2005). Water 60 and oil 70 are produced or pumped separately in this system to control coning. Again for heavier oils, the water pumping rate to control coning is very large and impractical.
There have also been attempts to limit the coning/cresting when reservoir characteristics are unknown or coning/cresting isn't large enough to justify prevention investments. Known remediation attempts have had limited impact. Examples of these attempts include the following:                (1) Blocking agents are used to inhibit water flow in the cone/crest zones. Blocking agents include gels, foams, paraffin wax, sulfur, and cement. Each of these have been tried with limited success (Piers (2005)), (El-Sayed, et al., Horizontal Well Length: Drill Short or Long Wells?, SPE 37084-MS, 1996).        (2) Another reactive process is to shut in the oil well that has coned/crested. Gravity will cause the cone/crest zone to re-saturate with oil. However, when the oil is heavier, the time for re-saturation can be very long and the benefits can be marginal.        (3) A slug of gas is injected into the cone/crest zone. In the early 1990's, a process called anti-water coning technology (AWACT) was developed and tested in medium/heavy oils (AOSTRA, AWACT presentation, March 1999). The AWACT process involves injecting natural gas (or methane) to displace water, followed by a soak period (Luhning et al, The AOSTRA anti-water coning technology process from invention to commercial application, CIM/SPE 90-132, 1990). Lab tests indicated that the preferred gas (CO2 or CH4) has some solubility in oil or water (FIG. 9). The following mechanisms were expected to be activated.                    a. On the “huff” part of the cycle or when gas is injected, methane displaces mobile water and bypasses the oil in the cone zone.            b. On the “soak” cycle or when the well is shut-in, methane absorbs slowly into the oil to reduce viscosity, lower interfacial tension, and cause some swelling            c. On the “puff” cycle or when the well is produced, gas forms ganglia/bubbles that get trapped to impede water flow. As illustrated in FIG. 5, this creates a change in relative permeability. Oil cuts are improved and oil production is increased.                        However, benefits only last a few years, and the process can only be repeated 5 or 6 times. Table 1 below summarizes AWACT field tests for 7 reservoir types (AOSTRA (1999)). Oil gravity varied from 13 to 28 API, and in situ viscosity varied from 6 to 1200 cp. AOSTRA suggested the following screens for AWACT—1) sandstone reservoir; 2) oil-wet or neutral wettability; 3) in situ viscosity between 100 to 1000 cp; 4) under saturated oil; and 5) greater than 10 m net pay.        
TABLE 1AWACT Reservoir CharacteristicsSouth Jenner AWACT Treatment Summary(Based on 34 treatments evaluated)Average ProductionAWACTAWACT Net ProductionAWACT Gas SlugPre AWACTPost AWACTDurationm3 oil/m3 waterSizeRatioWell GroupingMOPDOC %MOPDOC %MonthsOne YearDurationkm3m3m31.All wells3.09.72.919.92273/(7,900)315/(17,700)14422.02.30 wells with increased3.010.02.921.723102/(8,800) 365/(19,900)14822.0OC3.15 wells with increased2.511.73.825.523630/(11,100)1,350/(26,500) 14825.4MOPD4.19 wells with decreased3.47.92.215.221(370)/(5,400)  (510)/(10,700)  15120.1MOPD5.14 wells with increased2.612.04.127.523650/(11,700)1400/(27,900) 15433.0MOPD & OC6.10 water wetting treated2.99.43.319.028215/(8,700) 600/(24,800)11921.4wells7.23 non-chemically3.09.62.820.619 0/(7,800)165/(15,000)16727.4treated wells( ) numbers in brackets are negative* ratio is m3 gas per m3 of cumulative oil production prior to treatmentReservoir Characteristics of Other AWACT Treated PoolsNetWaterOilOilPayPermeabilityPorositySaturationGravityViscosityPressureRsl *FieldFormationmmdfrac.%° APIcpkPam3/m3Bellshill LakeBasal12-13 9000.230.29289.2590020Quartz/EllerslieProvostDina8.510000.220.35286.5n/a30Chin CouleeTaber7.6500-10000.200.30241408274n/aSuffieldUpper Mannville1610000.270.2513-14500876020ProvostMcLaren151000-50000.310.30131200n/a14JennerUpper Mannville12-161000-20000.260.2715-1766801033Grassy LakeUpper Mannville16-171000-20000.270.2317-1976960011* Initial Reservoir GOR                As illustrated in FIGS. 6 and 7, AWACT was not always a success (Lai et al., Factors affecting the application of AWACT at the South Jenner oil field, Southeast Alberta, JCPT, March 1999). As illustrated in FIG. 8, a test on a horizontal well was inconclusive (AOSTRA (1999)).        4) Cyclic CO2 stimulation is also a method to recover incremental oil. (Patton et al, Carbon Dioxide Well Stimulation: Part 1—A parametric study, JPT, August 1982). As illustrated in FIG. 10, process efficacy drops off dramatically for heavier oils.        Because of the limitations of the prior art, there is a need for a remediation process that reacts to the cresting/coning in oil wells, preferably heavier oil wells.        